This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
Field of the Invention
The present disclosure relates to the field of pressure relief valves. More specifically, the invention relates to a pressure relief system that is electronically controlled. In some aspects, the invention may be used in connection with a hydraulic fracturing operation or a downhole hydraulic jetting operation at a well site.
Technology in the Field of the Invention
In the drilling of an oil and gas well, a near-vertical wellbore is formed through the earth using a drill bit urged downwardly at a lower end of a drill string. The drill bit is rotated in order to form the wellbore, while drilling fluid is pumped through the drill string and back up to the surface on the back side of the pipe. The drilling fluid serves to cool the bit and flush drill cuttings during rotation.
After drilling to a predetermined vertical depth, the wellbore may be deviated. The deviation may be at a “kick-off” angle of, for example, 45 degrees or 60 degrees. This enables the operator to form multiple wellbores that penetrate a target formation from essentially a single well pad.
Within the last two decades, advances in drilling technology have enabled oil and gas operators to economically “kick-off” and steer wellbore trajectories from a generally vertical orientation to a generally horizontal orientation. This represents a 90-degree deviation. The horizontal “leg” of each of these wellbores now often exceeds a length of one mile, if not two miles. This significantly multiplies the wellbore exposure to a target hydrocarbon-bearing formation (or “pay zone”). For example, for a given target pay zone having a (vertical) thickness of 100 feet, a one mile horizontal leg exposes 52.8 times as much pay zone to a horizontal wellbore as compared to the 100-foot exposure of a conventional vertical wellbore.
FIG. 1 provides a cross-sectional view of a wellbore 100 having been completed in a horizontal orientation. It can be seen that the wellbore 100 has been formed from the earth surface 11, through numerous earth strata 20a, 20b, . . . 20h and down to a hydrocarbon-producing formation 30. The subsurface formation 30 represents a “pay zone” for the oil and gas operator. The wellbore 100 includes a vertical section 40a above the pay zone 30, and a horizontal section 40c. The horizontal section 40c defines a heel 40b and a toe 40d, along with an elongated leg there between that extends along the pay zone 30.
In connection with the completion of the wellbore 100, several strings of casing having progressively smaller outer diameters have been cemented into the wellbore 100. These include a string of surface casing 60 and one or more strings of intermediate casing 70. The casing strings 60, 70 are typically cemented into place, with a cement column being shown at 75. It is understood that while only one string of intermediate casing 70 is illustrated in FIG. 1, a deeper wellbore will likely have at least two if not three intermediate casing strings 70.
In addition, a lowest string of casing 80 is placed in the wellbore 100. The lowest string of casing 80, referred to as a production casing, is typically cemented into place as well. (See cement column 90.) In some completions, the production casing 80 has external casing packers (“ECP's), swell packers, or some combination thereof spaced across the productive interval. This creates compartments along the horizontal leg 40c for the isolation of zones and for specific stimulation treatments.
As part of the completion process and before a production tubing string is installed, the production casing 80 is perforated at a desired level 40c. This means that lateral holes are shot through the production casing 80 and the cement column 45 surrounding the casing 80. The perforations allow reservoir fluids to flow into the wellbore 40c. Where swell (or other) packers are provided, the perforating gun penetrates the casing 80, allowing reservoir fluids to flow from the rock formation into the wellbore 40c along selected zones.
After perforating, the formation 30 is typically fractured along the corresponding zones. Hydraulic fracturing consists of injecting water with friction reducers or viscous fluids (usually shear thinning, non-Newtonian gels or emulsions) into a formation at such high pressures and rates that the reservoir rock parts and forms a network of fractures 50. The fracturing fluid is typically mixed with a proppant material such as sand, ceramic beads or other granular materials. The proppant serves to hold the fractures 50 open after the hydraulic pressures are released. In the case of so-called “tight” or unconventional formations, the combination of fractures 50 and injected proppant substantially increases the flow capacity, or permeability, of the treated reservoir.
FIG. 1 demonstrates a series of fracture half-planes 25 along the horizontal section 40c of the wellbore 100. The fracture half-planes 25 represent the orientation of fractures 50 that will form in connection with a perforating/fracturing operation. According to principles of geo-mechanics, fracture planes will generally form in a direction that is perpendicular to the plane of least principal stress in a rock matrix. Stated more simply, in most wellbores, the rock matrix will part along vertical lines when the horizontal section of a wellbore resides below 3,000 feet, and sometimes as shallow as 1,500 feet, below the surface. In this instance, hydraulic fractures will tend to propagate from the wellbore's perforations in a vertical, elliptical plane perpendicular to the plane of least principal stress. If the orientation of the least principal stress plane is known, the longitudinal axis of the horizontal leg 40c is ideally oriented parallel to it such that the multiple fracture planes 25 will intersect the wellbore at-or-near orthogonal to the horizontal leg 40c of the wellbore, as depicted in FIG. 1.
In support of the formation fracturing process, specialized equipment is brought to the wellsite. This equipment may include, for example, water tanks, sand trucks, chemical tanks, and blenders. The blenders are used to mix the water, sand and chemicals. In addition, high pressure frac pumps are provided in order to inject the blended materials, or fracturing fluid, into the wellbore. A so-called hydraulic “frac” tree 65 may be installed over the wellbore 100 to receive the pressured fracturing fluid and direct it downhole.
As part of the equipment, a so-called “frac missile” (shown in FIGS. 8 and 9) is used to receive fluid from the various frac pumps. The frac missile acts as a fluid collections manifold, collecting the fracturing fluid from the fluid lines into a single high-pressure line. The high-pressure line directs the fracturing fluid from the high pressure frac tanks to the frac tree 65. In one arrangement, the fracturing fluids are directed to a separate frac manifold, which controls the delivery of injection fluids to a plurality of wells at a well site.
In any event, fracturing fluid is injected through flow control valves in the frac tree 65 and into the wellbore 100 at high pressures. Such pressures are frequently in excess of 5,000 psi and oftentimes in excess of about 12,500 psi.
Those of ordinary skill in the art will understand that fracturing fluids are not injected directly into the production casing 80; rather, they are injected through a working string, such as a string of coiled tubing (not shown). Bridge plugs may be placed along the wellbore in stages to direct fracturing fluid through the various production zones, sequentially. These bridge plugs may operate with balls that seal on seats, or may be resettable, or may be drilled out. The current inventions are not specific to any formation fracturing equipment used downhole.
The ability to form a series of fracture planes 25 along a single horizontal wellbore 40c has made the production of hydrocarbon reserves from unconventional reservoirs, and particularly shales, economically viable within recent times. Baker Hughes Rig Count information for the United States indicates only about one out of every fifteen (7%) of wells being drilled in the U.S. are now classified as “Vertical”, whereas the remainder are classified as either “Horizontal” or “Directional” (85% and 8%, respectively). This means that horizontal wells currently comprise approximately six out of every seven wells being drilled in the United States.
In most fracturing operations, a so-called “pop-off” valve is provided as a safety precaution. A pop-off valve is a relief valve that serves as a secondary pressure-regulating device. The pop-off valve (not shown) resides along or is otherwise in fluid communication with the high-pressure line. If the pressure-regulating device built into the fracturing pumps (or, optionally, the frac missile or the frac manifold) fails at a set system pressure, the hydro-mechanical pop-off valve will open and allow fracturing fluids to flow there-through before reaching the frac tree 65, thereby releasing fluids from the fluid injection system and relieving pressure.
Recently, more sophisticated pressure relief valve systems have been introduced to the industry. Specifically, KLX Inc. of Houston, Tex. has introduced a frac relief valve system, known generically as a FRV. The KLX FRV incorporates one or more gate valves that are operated by an accumulator system. U.S. Patent Publ. No. 2017/0285668 presents a version of a KLX FRV.
Safoco Inc., of Houston, Tex., has its own FRV. The Safoco FRV also utilizes a gate valve that is controlled by a “fail open” hydraulic actuator. In the FRV, pressure is sensed by two or more pressure transducers. The pressures at which the valve opens and re-closes are field programmable via a keypad interface. U.S. Pat. No. 9,671,794 is an example of a Safoco FRV.
FRV systems protect the integrity of the wellhead and reduce equipment failures such as blown tubing and cracked pumps. The FRV systems monitor pressures along the high-pressure line and seek to maintain pressure in the system at or below a rated limit for the associated fracturing equipment.
The known FRV systems rely upon gate valves, which are notoriously slow to open. In this respect, gate valves are opened and closed by applying numerous revolutions to an elongated, threaded shaft. In addition, gate valves can be slow and difficult to cycle during lubrication and maintenance procedures. Accordingly, an improved FRV system is needed for high pressure fluid injection operations at a well site wherein a valve may be opened rapidly with less than one complete revolution by an actuator. Further, a pressure relief valve system is needed that utilizes plug valves (or other single-revolution valves) instead of gate valves, and that may be scaled for use in connection with any high-pressure fluid injection system.